ARTICLE IN PRESS
Energy Policy 34 (2006) 3709–3718 www.elsevier.com/locate/enpol
A critical review of Iran’s buyback contracts Willem J.H. van Groenendaal, Mohammad Mazraati a
Centre for Resource and Environmental Studies, Tilburg University, The Netherlands b Organization of the Petroleum Exporting Countries, Vienna, Austria Available online 21 September 2005
Abstract Iran’s oil and gas industry requires investments of US$ 15 billion in the short term and over US$70 billion in the medium term. Iran tries to interest international oil companies (IOC) in investing in Iran’s oil and gas business by offering buyback contracts. Under a buyback contract an IOC invests and when production starts, the field is handed over to the National Iranian Oil Company (NIOC) or one of its representatives. The IOC gets its costs and an agreed upon profit paid out of the oil and/or gas gross profits, assuming the field produces as agreed upon and the international energy prices are high enough. According to the Iranian government, the buyback contract contains sufficient incentives for an IOC to invest in Iran. The IOCs, however, disagree. They claim that they solely bare the risks in a buyback contract, whereas the Iranian counterpart receives all windfall profits. Furthermore, the IOCs claim that the utilisation of Iran’s oil and gas reserves will be sub-optimal if they are not involved in optimising long-term recovery. In this paper, we investigate these claims and show that they are partly correct. Given Iran’s need for investment capital, Iran might have to change its policy. r 2005 Elsevier Ltd. All rights reserved. Keywords: Buyback contract; Risk sharing; Contractual framework
1. Introduction The National Iranian Oil Company (NIOC) is responsible for the development of Iran’s oil and gas resources, which are the second largest in the world. However, Iran lacks the capacity and financial resources to develop all its energy resources by itself, and therefore needs to cooperate with international oil companies (IOCs). Currently, Iran uses buyback contracts to affiliate with IOCs. (A buyback contract is basically a financing arrangement in which the developer sells a property to an investor and then buys it back under a long-term sales contract.) However, the IOCs are reluctant to cooperate and claim the Iranian buyback contract is not meeting their commercial requirements. The NIOC does not understand this and argues that within the buyback contract an IOC receives a fair return on its investment, without any technological (exploration and exploitation) risk. Corresponding author. Tel.: +31134662423; fax: +31134663069.
E-mail addresses:
[email protected] (W.J.H. van Groenendaal),
[email protected] (M. Mazraati). 0301-4215/$ - see front matter r 2005 Elsevier Ltd. All rights reserved. doi:10.1016/j.enpol.2005.08.011
The IOCs claim that under the current buyback contract they face several risks. If the international price of oil or gas is below an agreed upon level, the repayment of capital expenditures, bank charges, and/or remuneration is postponed. However, this price risk is only realised when prices are really low (for oil less than US$ 15/bbl in real terms). An IOC also faces other risks, such as higher capital expenditure requirements than agreed upon or its distribution over the construction period, or a production profile below expectations. All this affects the IOC’s rate of return, since under a buyback contract an IOC is not compensated for the postponement of payments, or for necessary expenditures above the amounts agreed upon in the contract. The IOC’s object the buyback contract also because within this contract they are only used to explore and/or develop until full production is achieved. After that, the NIOC takes over operation. The IOC’s role is reduced to supplying capital and acting as a technology service company (engineering, procurement, and construction). They argue that this is not the business they are in. Furthermore, they claim that the buyback contract will
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W.J.H. van Groenendaal, M. Mazraati / Energy Policy 34 (2006) 3709–3718
damage long-term field development, because the knowledge of the NIOC or its representative is insufficient for optimal long-term reservoir development. Oil and gas reservoirs require new investments during production due to changing reservoir behaviour. For this, the IOC’s expertise and funding is required again. However, without detailed knowledge of the reservoir behaviour over time, an IOC is not able to optimise the extraction over the lifetime of the reservoir. Because of this, they are in favour of other types of contracts. (For a discussion of modern concessions, production sharing agreements, or profit sharing agreements, see Bindemann (1999).) As is the case for production sharing contracts (PSAs), each buyback contract is different, because each reservoir faces different challenges and many factors need to be taken into account. Among these are technology transfer, optimising recovery, risk sharing, integration of up- and downstream activities, and maximising the benefits for the country. An issue that is not explicitly mentioned in the discussion, but definitely plays a role, is the fact that under a buyback contract, an IOC is not able to add to its portfolio the reserves they help to develop. As we know from Shell’s international reserves valuation problem, this is important for oil companies. In this paper we will, however, not discuss this issue. Note that the current political development, in combination with the fact that Iran is under US sanctions, decreases the attractiveness of Iranian projects also. This aspect is not discussed either. The main point of discussion between the NIOC and the IOCs is actually whether or not buyback contracts are fair, given the uncertainty of the different elements of the contract. This paper analyses the buyback contract for a single project, which is illustrated through a South Pars gas project in the Persian Gulf. The concerns of IOCs and the NIOC are discussed. Given Iran’s urgent need for investment funding, up to US$ 70 billion for the next 10–15 years, serious adjustment of the contract content is required to improve Iran’s long-term production. 2. Iran’s energy sector challenges Iran’s energy sector lacks a consistent and integrated policy package on the platform of a long-term strategic planning. Domestically energy is consumed inefficiently, causing rapid growth in domestic energy demand, and threatening oil and gas exports and thus revenues (Van Groenendaal and Moghaddam, 2002). In a country that is highly dependent on oil and gas income, this has a very negative effect on economic development. Since many of Iran’s investments in the energy sector are old, production has declined, contributing to an even larger decrease in revenues (Van Groenendaal and Moghaddam, 2002). Currently, this effect is somewhat clouded by the high international prices of oil, but it cannot be ignored.
Iran’s current production capacity is believed to be around 4.2 million barrels per day, down from over 7 million in 1979. It is forecasted that without investment in the upstream oil business this capacity will come down to less than 3 million barrel per day (Shell, 2003; IIES, 2003). Due to its very low domestic energy prices, based on the idea that all Iranian’s should share in the country’s resources, an increasing share of this production is consumed domestically. As a member of OPEC, Iran would like to keep its quota within OPEC in order to remain a key player on the international oil market. This is a major issue on the agenda of the Iranian government, the Ministry of Petroleum, and the NIOC. The aspiration level is to have a production capacity of 7 million barrel per day by the year 2020 (Mirmoezi, 2004) and to utilise the large gas resources by exporting it directly, tapping in on the increasing demand in Europe and the Far East, or after downstream activities. Based on various energy outlooks (EIA, 2005; IEA, 2004; OPEC, 2004), we conclude that there is a market for this oil and gas. The amount 7 million barrels per day of oil would guarantee Iran’s share in OPEC. To achieve such a high production profile, at least US$ 70 billion needs to be invested in the medium term (10–15 years) solely for the development of the upstream oil and gas business (Mirmoezi, 2004). This amount does not take into account the fact that other energy sub-sectors (gas, power, refineries), and most other sectors of the Iranian economy, need considerable investments too. To fund the oil and gas investments, Iran requires the support of IOCs. It is, however, questionable whether the country’s oil sector is able to attract sufficient support from IOCs under the current legal framework for oil and gas sector cooperation, known as buyback. The current buyback contract does not provide enough incentives for the IOCs to cooperate. Since the current system requires much discussion and negotiation, it is prone to corruption also. This is important since a transparent, regulated and internationally accepted system decreases moral hazard. In this respect, a more generic system for all upstream activities rather than project-by-project would be better. The legal system and contractual basis should take into account the long-term optimisation of all oil and gas activities. An example is the experience in the North Sea, where clear legal systems and international cooperation has lead to extremely high recovery factors. The cooperation between IOCs and governments in the North Sea, all working together, resulted in maximum revenues for the IOCs as well as the countries. 2.1. An update of buyback projects and their outcomes Because Iran needed to modernise its energy sector, the autarkic policy formulated after the Islamic revolution in 1979 was abandoned in the mid 1990s. IOCs were invited
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to invest in Iran’s oil and gas sector. To prevent foreign control over its resources, which is forbidden by law, Iran introduced the buyback investment program. American based Conoco Oil Company signed Iran’s first buyback contract. However, in 1995 and 1996 the Clinton administration implemented economic sanctions against Iran, which are known as the Iran and Libya Sanctions Act or ILSA (Katzman, 2003). (In 2001, the Bush administration renewed this policy.) The aim of this policy is to prevent investments by American as well as non-American firms in Iran’s economy, especially the energy sector. As a result, the Conoco contract was cancelled before implementation. ILSA allows the US president to waive sanctions when doing so is important to the USA’s national interests. When the French company Total SA and partners took over the Conoco deal and agreed to invest some US$ 2 billion in phases 2 and 3 of the South Pars gas field, a deal between the Clinton administration and the Chirac government waived the sanctions and a contract, with better conditions and incentives than the Conoco agreement, was signed. After that, the activities of IOCs, mostly from Europe, in Iran’s upstream oil business increased. However, due to Iran’s cooperation with many IOCs, resulting in increased competition, but even more due to domestic opposition to foreign investments, the content of buyback contracts gradually changed. The rewards and returns on investments by IOCs are currently less than under the early buyback contracts. According to Katzman (2003), Iran reached oil and gas agreements in excess of US$ 8 billion between 1999 and 2002, although it is unclear whether or not all of these were a success. According to the IIES (2003), the total amount of investment in oil enhancement projects between 1999 and 2005 is US$ 3.5 billion, aiming at an increase in production by 407.6 thousand barrel per day by the end of this year (2005). For Iran, the development of the South Pars gas field (estimated at 280–500 TCF) for export is of major importance. With the increasing demand in the Far East and Europe there are ample opportunities. As Table 1 shows, development of the South Pars’ gas field phases 1–8 require more than US$ 7.2 billion in investments and more than US$ 6.5 billion in remuneration and interest charges; a total of US$ 13.7 billion in financial commitments for the country. Tables A1 and A2 in the Appendix A summarise the oil and gas buyback contracts between 1999 and 2003. It is for the improvement of its obsolete oil technology and the development of its huge gas reserves for export that Iran needs at least US$ 70 billion over the next 10–15 years. 3. Outline of a buyback contract A buyback contract is basically a service-type contract under which a foreign company develops an oil or gas resource and is repaid from sales revenues, but has no share in the project’s profit after being repaid. Once started producing, the investment is handed over to the NIOC (or
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its representative) who will operate and manage it. There are fundamental differences between a buyback and production sharing agreement. In the latter, an IOC does receive a share of the future profits (either in money or in kind) and normally operates the field. Because of these differences, the Iranian service contract is called buyback. An Iranian buyback contract contains four main elements. First, the contract will stipulate the annual capital expenditures, (say) At , during the investment period 0, y , T., so the total investment by the IOC that needs to be P repaid after year T is Tj¼0 Aj . Let Dt be the repayment of the investment in year t4T. The amount that needs to be repaid in year t, TRt , is TRt ¼ TRt1 Dt ¼
T X
Ai
i¼0
with t4T and
T X i¼0
Ai X
t X
Dj ,
j¼Tþ1 t X
Dj .
ð1Þ
j¼Tþ1
TRt ¼ 0 once the investment has been repaid or T X i¼0
Ai
t X
Dj .
j¼Tþ1
Note that an IOC has to pay duties on imports, which will affect the At . These import duties will be reimbursed after the project has been handed over to the NIOC. Second, bank charges on the amount invested have to be paid. In year þ 1, interest during construction amounts P TP to IC T ¼ i Tj¼0 jl¼0 Al . In a buyback contract, the interest rate i, used to calculate the bank charges, is based on the London Inter Bank Offer Rate (LIBOR) plus a premium of up to 1%. (This percentage is rather low given the risks involved in oil and gas projects.) After construction, bank charges have to be paid on TRt also. Let C t be the NIOC’s annual payment on bank charges, then the total bank charges still to be paid, IC t , are IC t ¼ rTRt þ rIC t1 C t ; with t4T and IC t1 40.
(2)
The first term rTRt are this year’s bank charges over the amount invested and not yet repaid, the second term rIC t1 are bank charges over the bank charges not yet repaid, and the third term is the agreed upon annual payment of bank charges. Once C t ¼ rTRt þ rIC t1 , IC t ¼ 0 and will remain so. Third, a buyback contract will contain remuneration, Bt , for the IOC’s efforts. These payments will take place during an agreed upon time period T+1, y , I. Within this period also, the repayment of the investment and the bank charges will be settled. PIt is usually between 7 and 12 years. Total remuneration It¼Tþ1 Bt is the amount paid to the IOC as a reward for its services, which include engineering, procurement, and construction of the project, the financing thereof, and the transfer of the agreed upon technology. The payment actually starts after the development is completed and the products (oil, gas, condensate, LPG, ethane, and sulphur) become available for marketing.
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3712 Table 1 South Pars gas buyback contracts
Unit Phase 1 Phases 2 and 3 Phases 4 and 5 Phase 6–8
Investment
Targeted IRR
Bank charges
Remuneration
ROCa
MM $ 730 2012 1896 2650
% — — 13.94 12.00
MM $ 80 807 825 1010
MM $ 130 1400 1074 1224
% 28.8 109.7 100.2 84.3
Source: IIES (2003). a Return on capital expenditure (CAPEX) in money of the day.
Total remuneration is normally about 50–60% of the amount invested. Fourth, a buyback contract will contain an agreed upon internal rate of return for the IOC (say) rIOC , which is subject to negotiation but normally somewhere between 12% and 15%. This internal rate of return is based on the agreed upon investment (Ai , i ¼ 0, 1, y , T) and production schedule and affected by the elements Bi , C i , and Di . The scheduling of all elements in a buyback contract is subject to negotiations between the NIOC and the IOC. The outcome of this process will differ per project and depends to some extent on the NIOC’s and IOC’s risk attitude. This is similar to the wide variation of stipulations in, for example, production sharing contracts used around the world. To achieve the agreed upon internal rate of return rIOC , remuneration Bl , bank charges, C l , and repayment of the investment, Dl , with l ¼ T+1, y , I, are set to achieve NPV IOC ¼
T X t¼0
I X At ðBl þ C l þ Dl Þ ¼ 0. tþ l ð1 þ rIOC Þ l¼Tþ1 ð1 þ rIOC Þ
(3)
J X
Pjt Qjt OM t .
(4)
j¼1
Pjt stands for the price of product j in year t and there are J products (oil, gas, condensate, ethane, sulphur, etc.) in total; Qjt denotes the quantity of product j produced in year t; and OM t denotes operating and maintenance costs. Of the annual gross profits GPt , only a fraction j is available for payments to the IOC. This results in the constraint jGPt XðBt þ C t þ Dt Þ,
NPV NIOC ¼
This investment takes T þ 1 years and production starts at the start of year T þ 1. Given the number of degrees of freedom in setting (Bl , C l , Dl , I), there are many solutions to this problem, so there is ample room for negotiations even after the investment schedule (A0, y , AT) and rIOC have been set. Note that Eq. (3) does not contain taxes, because an IOC does not have to pay tax on the remuneration in a buyback contract. The projects gross profits GPt can be defined as GPt ¼
where ðBt þ C t þ Dt Þ is the total annual payment to the IOC. So the total payment in year t is only j GPt in case j GPt oðBt þ C t þ Dt Þ and ðBt þ C t þ Dt Þ elsewhere. Only if Eq. (5) holds at all times (T+1, y , I), the agreed upon IRR for the investor is guaranteed. Otherwise (part of) the payments will be postponed, and there is no compensation for this postponement. Buyback contracts do not allow for payments from financial resources other than the project’s net revenues. Normally j ¼ 0:6 in a buyback contract, meaning that 40% of total gross profits is for the NIOC no matter what. This is similar to royalty in-kind in a production sharing agreement. (For a thorough discussion of production sharing agreements see Bindemann, 1999.) Once the schedule for investment, the bank charges, remuneration, and repayment of the principal investment is known, one can calculate the cash flows and net present value of the project for the NIOC. For the NIOC, the repayments are additional costs of the project. Therefore, the NPV for the project from the NIOC’s point of view is
(5)
P L ð J P Q OM ðB þ C þ D ÞÞ X t t t t j¼1 jt jt
t¼Tþ1
ð1 þ rNIOC Þt
.
ð6Þ
rNIOC denotes the NIOC’s discount rate; L is the evaluation period for the investment, based on the estimated productive lifetime of the investment. When approaching L, production may not be economically optimal, and additional investments for secondary recovery are normally required earlier. However, in our analysis of the initial investment, we do not take this aspect into account, because these adjustments are not included in a buyback contract either. Note that Eq. (6) does not contain taxes. Although the NIOC has to pay several taxes and royalty, these are of no importance to our analysis since they are only agreements to redistribute the country’s project revenues among what are effectively different parts of the government. In this respect, Eq. (6) resembles the economic net present value, i.e., the projects value to the country, rather than the financial net present value, which represents the value of the project from a private investors point of view (Van Groenendaal, 1998). A buyback contract is based on build and transfer; so once production starts, the IOC leaves the project and the
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NIOC becomes the operator. If the technology transferred and the production profile are based on best practise, and the reservoir is treated according to good reservoir engineering principles, a buyback contract will bring maximum benefits to the state from a single project point of view, together with a reasonable return for the IOC, which acts as an engineering company. 4. Identifying an IOC’s risks In general, limitations or constraints are absent in a buyback contract. However, this does not hold for the current Iranian buyback contracts. The Iranian contracts stipulate that payback can be postponed if the revenues from the investment do not cover the amount the investor is entitled to for that particular year. This can occur due to underestimation of the investment required or the timing thereof, overestimation of production (a lower than expected production profile or accidents during production), and/or low prices on the international oil and/or gas markets. (Only if the actual investment is less than agreed, benefits are shared but normally the IOC is entitled to a maximum of 10% (Wells, 2002).) The investor is not compensated for postponement of payments that may result from realisation of these risks, which obviously constitutes a risk for the investor, since it reduces the agreed upon internal rate of return rIOC. For the NIOC, some of these risks are less or absent; for example, higher capital expenses than agreed upon, since they are compensated out of the IOC’s remuneration. Because of the stochastic nature of Pjt , Qjt , and OM t in Eq. (4), there are clear risks for the investor under a constrained buyback contract. The IOC and the NIOC base a buyback contract on an oil price of US$ 15 per barrel. The NIOC would like to raise this price to US$ 20 per barrel, but the IOCs object this. The reason for the objection is that the risk of insufficient gross profits will increase when the threshold price increases. The prices of other products produced (condensate, sulphur, etc.) are linked to the threshold price. For example, the price of condensate per barrel could be the price of oil, Poil , plus 1 US$. For natural gas, there normally is no specific price per unit in the buyback contract, the contract just states the agreed upon remuneration and internal rate of return. The actual price of oil or related products, Pjt , is beyond the investor’s control. So if the real price is below the threshold price of US$ 15 at any time during the period [T+1, I], the IOC loses money. Of course this also holds for the NIOC. However, since the evaluation period for the NIOC (L) is much longer than the evaluation period of the IOC (I), the NIOC has more opportunities to compensate possible ‘‘losses’’. The reliability of the production profile estimate (Qjt ) is strongly related to the IOC’s expertise. Since the production is handed over to the NIOC, operating and maintenance costs (OM t ) are also beyond the control of the IOC. If these costs (that are paid by NIOC during the operation) are higher than expected, there is a risk of
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insufficient net cash flow for reimbursement of the IOC. However, operating and maintenance costs are usually small in Iran, less than 3% of capital expenditure. Based on our discussion, we conclude that a constrained buyback contract contains the following elements of risk to the IOC:
prices below the agreed upon threshold, capital expenditures above what was agreed, delay in construction, production profile below expected, cut in production due to accidents, and higher than expected operation and maintenance costs.
Realisation of one or more of these risks will affect the IOC’s internal rate of return rIOC in Eq. (3). These variables are of course not much different from the risks in, for example, a production sharing contract. What is different is the fact that if a project does worse than agreed upon on any one of these aspects, the IOC’s income is affected, whereas the IOC does not share in windfall profits,i.e., profits that exceed the profits based on the stipulations in the contract. Only a positive difference between the total investment agreed upon and the actual investment might be shared between the IOC and the NIOC. This policy means that potential positive and negative effects caused by deviations in different variables within a project cannot mitigate one another. Furthermore, low prices in one period will be normally offset by high prices in another. Within a buyback contract, this is, however, not the case for the IOC. This brings us to another aspect. IOCs invest in a portfolio of projects. Their aim is a healthy return on the portfolio. Given the fact that the outcome of each project is (somewhat) uncertain, project-specific uncertainties will normally mitigate each other within a portfolio. In case of a portfolio of buyback contracts, this is, however, not the case due to the fact that all positive effects accrue to the NIOC. Of course this does not hold for non-projectspecific uncertainties like prices, since all projects are affected similarly. Finally, in some cases, a field has been divided in different blocks and awarded to different investors such that savings in total investments could have been achieved if the entire area was awarded to one capable company. Although not discussed above, there are also some elements of risk that the NIOC faces:
Sub-optimality in engineering to achieve a high production profile at the early stage to assure the sufficient revenues during early production. P Overestimation of capital expenditure ð Tj¼0 Aj þ PT Pj i j¼0 l¼0 Al Þ to increase remuneration and bank charges. Non-integrity of up- and downstream activities, which provide a major element of risk for the downstream activities.
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These factors are, however, non-visible and cannot be quantified within a single project. 5. Evaluation of a buyback contract In order to numerically evaluate the issues of a buyback contract as discussed above, we discuss an investment in a gas field. The data and assumptions used (see Table 2) were taken from different sources including the Ministry of Petroleum and closely resemble an investment project in Iran’s most important gas development, the South Pars gas field. Since actual buyback contracts are confidential, the data and assumptions in Table 2 differ from those in any singed buyback contract. For the points we want to illustrate, this is, however, not a problem, since it does not affect the methodology, analysis, or the conclusions.
Using Eq. (3) and the assumptions in Table 2, a payment schedule (Bt , C t , Dt ) for the IOC can be obtained; see Fig. 1. In our example payments start in 2005, so T+1 ¼ 2005. The payment schedule is based on the threshold price of US$ 15 per barrel in dollars of 2001. We assume, as was the case in several contracts, that the payment in year T þ 1 is used to repay interest during construction (US$ 357 million) and part of the interest in year T þ 1 (US$ 52 million). For the repayment of the investment (Di ), we used the average schedule of several contracts and these payments start in year T þ 2. Furthermore, with annual capital expenditures, the agreed upon internal rate of return rIOC, and the bank charges known, we can calculate remuneration. The total repayment period is 11 years [2005–2015], but the remuneration has priority in this contract and US$ 190 million is paid for 6 years starting in 2006.
Table 2 Data of a typical buyback contract for the development of one phase of South Pars Item
Comments
Investment period Repayment period Capital expenditure (Investment) (Interest) Remuneration Bank chargesa Targeted IRR for IOC Gas productionb
5 years 11 years US$ 1880 million (US$ 1523) (US$ 357) US$ 1140 million US$ 1242 million 12.5% 50 million m3 per day
Condensate productionb Sulphur productionb Condensate price Sulphur price
80 000 bbl per day 140 ton per year ¼ Brent+1 per barrel US$ 15 per Ton
a
CAPEX is distributed as 3%, 19%, 38%, 27%, and 13%
60% of CAPEX LIBOR 6.5%+1% premium Only downward adjustment Production profile of 20 years, after 10 years production declines and finally reaches 25 MM m3 per day
Mobasser (2000), Scrutinizing Petroleum Investments: Buyback Contracts. Kavir Publication, Tehran, Iran (in Farsi). Ministry of Petroleum of Iran (2002), Oil and Development II: Report on Petroleum Ministry Performances. Tehran, Iran (in Farsi).
b
650
Million US$
450
250
50 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 -150
-350
-550
-750
CAPEX
Remuneration
Repayment of CAPEX
Bank charges
Available for repayment
Net revenue
Fig. 1. Distribution of revenues in a general buyback contract.
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Internal rate of return
Net present value
12%
250 200
10% 8%
150
6%
100
4% 50
2% 0% 0
0.5
1 1.5 Delay : Year
2
NPV in million US$
14%
IRR
Many solutions are possible, but normally a contract aims at (Bt þ C t þ Dt ) ¼ constant, which is US$ 409 million in this example, with the exception of the last payment. The period for repayment of the principle investment is over a period of 10 years, which in Iran is also used for depreciation in case of private investments. The priority of payments for the principal investment, remuneration and bank charges, as long as they meet the constraint of 60% of annual profits (Eq. (5)), is arbitrary and a matter of negotiation between the parties. Some companies prefer receiving the remuneration and bank charges in early stages of production. Fig. 1 does, however, closely resemble actual buyback contracts. In this example, the return on invested capital (ROIC), net income over invested capital, for the IOC is 127%, which gives an annual average of 11.5% for the repayment period of 11 years. The net present value at a 10% discount rate is US$ 216 million. To assess the aforementioned price risk and the risk of a delay in the development phase, we evaluated these two events and their effect on the IOC’s cash flow. The price risk is a result of Eq. (5), where repayments are postponed if the gross profits of the project are less than an agreed upon minimum. In the case of a delay in the construction phase, the revenue stream starts later than expected, which is not compensated in terms of extra bank charges and/or remuneration. When prices (of oil, gas and other byproducts) are sufficient, the cap in Fig. 1 has no effect. In this case, the overall internal rate of return of the total project increases, but this has no effect on the cash flows and thus rIOC, the internal rate of return of the IOC, since an IOC does not share in additional profits. When prices decrease the revenue comes down, which in turn triggers the restriction. In this case, a portion of the agreed upon payment schedule is postponed till the gross profit is large enough again to repay the IOC. This effect is shown in Fig. 2, where lower prices result in a decrease in the IOC’s internal rate of return, whereas the IRR is fixed when prices rise above US$ 15 per barrel. A price of less than US$ 15 per barrel in prices of 2001 seems unlikely under the current high prices, but it is only 6 years ago that they were below this price for some time. An increase of Iran’s production to 7 million barrels per day and Iraq’s
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0 2.5
Fig. 3. Effect of a delay in construction on the IOC’s internal rate of return and the net present value in a gas buyback contract.
production getting on stream (approximately another 5 million barrels per day), eventually in combination with reduced growth in the Far East, could result in low prices again. Note that a lower production profile than agreed upon will have a similar effect as continued lower prices do (lower gross profits), so we will not discuss this effect separately. Fig. 3 shows the effect of a delay in the development of a field on the IOC’s internal rate of return and the NPV. Per 6 months delay there is a reduction of the internal rate of return by approximately 0.5% points. A delay of 1 year reduces the NPVIOC from US$ 216 million to US$ 101 million, and 1 year extra to US$ 25 million. Figs. 2 and 3 show that there is a clear risk for an IOC, which can neither be compensated within a project nor by other projects, as is the case for production sharing contracts. What when two or more risks come together. For example, a reduction in gross profits (caused by a low price or lower than expected production) and a redistribution of investment (so no increase). Assume the amount available for repayment during the period [2005–2015] is 9% less than agreed upon. This will reduce the NPV by almost 79%. If the investments in year 1 and 2 each require US$ 200 million extra, but years 3 and 4 require US$ 200 million less, so total investment is the same, the NPV is reduced by 33%. When these two events happen, the NPV becomes negative and the internal rate of return of the IOC reduces by 2.4% points.
25.0
6. Discussion
IRR %
20.0 15.0 10.0 5.0 Internal rate of return of the project
Internal rate of return of the IOC
0.0 0
5
10
15
20
25
30
35
Brentoil price($ bbl)
Fig. 2. The effects of price changes on the IOC’s internal rate of return.
Although the Iranian government is right when it states that the buyback contract rewards an IOC sufficiently, our analysis shows that this is only correct if the estimated gross profits are actually realised and the investment is finished as planned at the agreed upon costs. In case of overestimation of revenues or underestimation of costs, the IOC carries the risk. This is because an IOC is not compensated for differences between the stipulations in the contract and the realisation thereof. The claim of the
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Iranian government that an IOC is sufficiently rewarded would be correct only if an IOC would be paid the agreed upon amounts irrespective of the actual project results. This is not the case. As a result, an IOC is exposed to risks related to the project (larger than agreed capital expenses, lower production profile, higher operating, and maintenance costs), as well as a market risk (low energy prices). If the Iranian government does not want to guarantee repayment, a buyback contract could make provisions for compensating the IOC for realised risks out of profits resulting from prices that are higher than the ones used in the contract. In this way, project risks and profits can offset each other, and the price risk can be mitigated by higher payments after a period of low prices also. If none of the risks becomes real, the compensation is as agreed upon in the contract. If one or more risks realise, the IOC is compensated in case there are ‘‘extra’’ profits, this to achieve the agreed upon internal rate of return rIOC. Another possibility is of course to adjust the internal rate of return for risk, which means agree on a higher rate. Since an IOC’s claim would be on money, not the actual resources, these solutions would be within Iranian law. IOCs are used to deal with these types of risks and contracts. Furthermore, this is not an unconditional share in future profits, which is yet another way to deal with the problem and a step closer to a production sharing contract. Only with adequate adjustments of the buyback contract will Iran be able to increase the participation by IOCs and raise the US$ 70 billion required for its oil and gas industry. Since the IOC’s involvement in the project stops after commencement, they have to trust the operator will optimise the field. With the operator having stakes in many fields and dealing with many IOCs, this might not be the case. Also the volatility of the international oil markets makes it difficult to reliably estimate production profiles, future prices, and cost issues. Aspects in case of a production sharing agreement are better covered because the risks and windfall profits are divided between the IOC and the national oil company. Another aspect that is insufficiently taken into account in the buyback approach is the long-term optimisation of
oil and gas recovery. Although the NIOC or one of its affiliates might be equipped for the job, it is questionable whether local companies will be able to use and maintain the technologies that are developed in other areas of the world. For example, recovery factors in the North Sea are more than 40%, based on modern ICT-driven technology. It is questionable that Iranian companies will be able to achieve these recovery factors. Only with the continuing help of IOCs or international engineering companies, they might get some of the technology. What are missing in our analysis so far, are the macroeconomic consequences of the buyback approach. Till now we have looked only at the field level. With a short-term investment requirement of US$ 15 billion and a total of US$ 70 billion for the next 10–15 years, Iran will need all the help it can get. Without sufficient investments by IOCs, Iran will not be able to improve its production capacity. But there is more to it. Without sufficient capital input, Iran will also not be able to invest in the improvement of its domestic energy sector, which will remain a drain on its export capacity. Finally, an IOC has many investment opportunities and only limited funds. The Shell resource scandal has shown once again how important oil reserves on their balance sheet are. Under other contract forms, that do not overcompensate the IOCs or necessarily give them a claim to a country’s resources, both the IOC and the country seem to be better off. We are convinced that this is a winwin situation for both on the project level, but also when analysed on the macroeconomic level. The next steps in this research will be an augmentation of the analysis on the field level by including the stochastic character of the problem, and a thorough analysis on the macroeconomic level.
Appendix A Oil recovery enhancement buyback contacts and gas development buyback contracts are given in Tables A1 and A2.
316 MM bbl 3.4 MM bbl —
69 000 bpd
5278 bpd
407 637 bpd
Gas Prod. 25 MMCM/d and 40000 bpd condensate Gas Prod. 50 MMCM/d, 80000 bpd condensate, and 400 ton sulphur Gas Prod. 50 MMCM/d, 80000 bpd condensate, and 400 ton sulphur Gas Prod. 80 MMCM/d for injection, 1.2 MM ton/Y liquefied gas, and 120 000 bpd condensate
South Pars phase 1
2650 MM$
1896 MM$
2012 MM$
730 MM$
Investment
—
1074 MM$ (repayment 7–10 years) 1224 MM$
1400 MM$
130 MM$
1010 MM$
852 MM$ (@ LIBOR+0.75%)
807 MM$ (@ LIBOR+0.75%)
80 MM$
Bank charges
PetroIran
PetroIran
2001–2004(I)–2006(II) NESCO & Sheer Energy
Petropars
AGIP, Petropars
Total, Gasprom, Petronas
Petropars
Contractor
Elf petroleum Iran (46.75), Bow Valley Iran Ltd (15%), AGIP Iran B.V( 38.25) TotalFinaElf (55%), AGIP(45%) PetroIran AGIP Iran B.V.
Shell Exploration B.V.
Contractor
Remuneration
3.5 billion $
160 MM$
395.7 MM$
70.2 MM$
540 MM$ 850 MM$ 548 MM$
169 MM$
799 MM$
Investment
Maximum annual repayment is 574.6 million dollar available from sale of condensate and LPG; targeted IRR for the investor is 13.94%. Targeted IRR for investor is 12%.
b
a
South Pars phaseb 6–8
South Parsa phase 4 and 5
South Pars phase 2 and 3
Objective
—
343(F) & 11(E) million bbl 259(F) million bbl
—
2.5 billion bbl 450 million bbl —
117 million bbl
1.05 billion bbl
Recoverable oil
Filed name
Table A2 Gas development buyback contracts till March 2003
Source: Iran Energy Report 2003, IIES, 2003, www.iies.net.
—
20 000 bpd
Masjed Suleiman Froozan & Esfandiar Nosrat & Farzam Total
4.96 MM bbl 15.9 MM bbl —
14 434 bpd 16 649 bpd 50 000 bpd (I); maximum 160 000(II) bpd
1.38 MM bbl
21 334 bpd
Doroud Salman Darkhoyin
24.76 MM bbl
50 942 bpd
Soroush & Nouruz Balal
Cumulative production
Production increase
Field name
Table A1 Oil recovery enhancement buyback contracts
2000–2006
2003–2008
1997–2003
1998–2002
Start–finish
—
2000–2003
2003–2005
2002–2004
1999–2004 2000–2005
1999–2003
1999–2003
Start–finish
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References Bindemann, K., 1999. Production Sharing Agreements: An Economic Analysis. Oxford Institute for Energy Studies WPM 25. EIA, 2005. Annual Energy Outlook 2005. Energy Information Administration, US Department of Energy, Washington, DC. IEA, 2004. World Energy Outlook. International Energy Agency. IIES, 2003. Iran Energy Report 2003. www.iies.net. Katzman, K., 2003. The Iran-Libya Sanctions Act (ILSA). Congressional research service; foreign affairs, defense, and trade division. CRS Report for the Congress, Order Code RS20871. http://fpc.state.gov/ documents/organization/23591.pdf. Ministry of Petroleum, 2002. Oil and Development II: Report on Petroleum Ministry Performances. Ministry of Petroleum, Tehran, Iran (in Farsi). Mirmoezi, 2004. Role of Middle Eastern NOCs in world oil industry and necessity of structural reforms and productivity. Ninth international
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IIES Conference, Proceedings of the Conference, Tehran, Iran (in Farsi), also available on www.iies.org. Mobasser, D., 2000. Scrutinizing Petroleum Investments: Buyback Contracts. Kavir Publications, Tehran, Iran (in Farsi). OPEC, 2004. Oil & energy Outlook to 2025: OWEM Scenario Report. OPEC Secretariat, Vienna, Austria. Shell, 2003. An in-house presentation to the NIOC’s Corporate Planning Department on upstream business in Iran. Van Groenendaal, W.J.H., 1998. The Economic Appraisal of Natural Gas Projects. Oxford University Press, Oxford Institute of Energy Studies, Oxford, England. Van Groenendaal, W.J.H., Moghaddam, R., 2002. Iran’s energy mix in perspective. In: Proceedings of the 25th Annual Conference of the International Association of Energy Economics, Aberdeen, Scotland, 26–29 June 2002, pp. 1–9. Wells, P.R.A., 2002. Buyback & production sharing agreements: what is the difference? IIES Conference, 9–10 December, Tehran, Iran, available also on www.iies.net.
